Amplify Energy Corp. (AMPY) Earnings Call Transcript & Summary

Welcome to our fireside chat today with Amplify Energy. My name is Jeff Grampp. I'm the senior research analyst covering energy at Alliance Global Partners. With me today from Amplify are CEO, Martyn Willsher; its CFO, Jim Frew; and its COO, Dan Furbee. The format for today's call will be to let management begin with some opening remarks. I'll then moderate the Q&A session. If you have any questions, you can either submit it through the Zoom platform at the bottom of your screen or if you'd like to e-mail me directly at [email protected], that works as well. We're also going to be recording today's webinar for a replay that can be available at a later time. So with that, I will turn it over to the Amplify team to kick us off with an overview of the company as well as cover the exciting news from last week, which was a pretty material acquisition of some oil-weighted Rockies assets. So this call is well timed to discuss that as well. So guys, I'll let you kick us off.

Great. Thank you, Jeff. This is Martyn Willsher, I'm the President and CEO. To my right here is Jim Frew, our CFO. Across from me is Dan Furbee, our COO; and Michael Jordan, our Treasurer. We'll be the team to kind of walk you through everything today. Given that some people may be more familiar with the company than others, I'd like to start by just kind of introducing the company. If we can go to Slide 6, talking through kind of the various assets, and then I'll kind of finish with the merger asset and move on from there. So if you look at Slide 6, the what I'll call legacy Amplify portfolio is basically numbers 2 through 6 of this list, starting with Oklahoma, which is a kind of a mature mix of oil, gas and NGLs. It's been the Mississippi Lime play, kind of Northwestern Oklahoma. It's an asset that we acquired through a merger with Midstates back in 2019. It's an area that we've done a really good job of kind of lowering operating costs and managing production decline. It's not an area where we have a lot of organic development opportunities, but it's an area that we've been able to manage through workovers and have lowered operating costs through a series of rod pump conversions and water handling changes and surface agreement changes. And so it's certainly something where we've kicked off a lot of cash flow, but not a big driver from an organic growth perspective. Looking at #3, we'll call this kind of the legacy Rockies asset. This is a CO2 flood in Bairoil, Wyoming, which has a population of less than 100 people. So it's kind of in the middle of nowhere. This is an area that has been on some kind of flood for probably 50, 60 years. It was started as primary recovery, and then waterflooded and then later, CO2 or tertiary flooded 30, 40 years ago now. This is an area that's got long kind of steady oil production, but it's also an area with relatively higher fixed costs. And so it's an area that does extremely well and has strong margins when oil prices are up, but it's an area that can get squeezed a little bit when oil prices go down. It does have the benefits, like I said, of being very much all oil but, once again, has a little bit less organic development opportunities, although we found some that we'll be looking at more in earnest in 2025 and ways of trying to lower some of these fixed costs while also kind of supplementing some of the incremental oil production from this area. I'm going to skip 4 for now, go to #5 for East Texas, North Louisiana. This is kind of the legacy asset of all the legacy assets. This is our kind of core asset when the predecessor company was founded all the way back in 2011. This is largely gas. I think it's probably about 70% gas, 27% NGL, something of that nature, and a few percent condensate. We're basically in the Cotton Valley formation for the most part, in most of our production, although we do have some Haynesville rights across areas in East Texas where it's becoming more prospective over time as people have kind of drilled up a lot of the North Louisiana area and they're kind of coming into the East Texas area and kind of following the Haynesville trend into our area. Unfortunately, we don't have Haynesville acreage across all of our acreage, but there are some areas that are more prospective, and we're looking at ways to create value from the acreage that we have out in East Texas. But like I said, this is a gassy area. Obviously, gas is much better this year than it's been in recent years, but it's been highly volatile on the gas side between well over $4 a couple of years ago to now low $2s probably on average last year. So we tend to hedge gas pretty aggressively in order to kind of smooth those out. And so you'll see kind of we have a large percentage hedged on our gas production just to kind of make sure that we're locking in solid margins on this particular position. In the Eagle Ford #6, this is an area where we have a non-op interest in what's primarily Murphy-operated wells down in the Eagle Ford in the middle of Karnes County. Excellent acreage, a lot of wells have been drilled at this point, we only have typically about a 5% working interest in most of the new drill wells. Some of the older wells, we have a 20% working interest. And so when they've been doing refracs, which they've been doing more frequently lately, we've had a larger working interest in several of those. So it's still an area that has some good upside. And certainly, we like to participate whenever they propose something that makes sense. But unfortunately, just from a materiality perspective in terms of the overall portfolio, it's fairly small. So like I said, great area to kind of participate in, very little overhead required, but fairly small relative to the rest of the assets. So I'll take you back to Beta, which is asset #4 on this list. This has really been the focal point of the company over certainly the last year and probably even before that in terms of potential upside opportunities. This is an area that's offshore, in federal waters. It's an area where it's all oil production. It's fairly heavy crude, kind of 15-degree API gravity oil and below, in some cases. We sell into the markets just there, onshore, in kind of the Port of Long Beach and Los Angeles. There are several refineries kind of in that complex, and that's where we basically sell our crude into. Last year, we kicked off a development program in this area based on the fact that there's a lot of remaining oil in place. Historically, this has been developed largely vertically and perforated across essentially 6 different producing intervals. We are focusing on drilling into and producing from one producing interval with kind of more longer -- well, not long laterals from onshore. These aren't 5,000-, 10,000-, 15,000-foot laterals, but laterals through kind of these producing areas where you're getting the best productivity. And so we're trying to obviously hit more of the reservoir where it's the most productive. Before kind of our last earnings call in November, we drilled 2 really productive wells, the A50 and the C59. Those wells were producing well above our internal type curves, well in advance of where we projected them to be from a reserve report perspective. This has given us more confidence as we move on to our 2025 drilling program. There was an additional well that we'll be able to report on in early March as we give up all of our information on kind of the fourth quarter results. So we'll have an additional well from that. And then we've been working really hard on not just kind of setting up the 2025 program, but doing some workovers, doing some adjustments to the wells we completed in 2024, really kind of getting this area all set up for a new drilling program in 2025, taking the lessons we learned from what is essentially a drilling program that's never been done before out here and really taking the lessons that we've learned and applying it to this new drilling program in 2025. So it's an area we're really excited about. It's certainly an area I think a lot of our investors are excited about because all the production out here is largely, because of the higher fixed cost area when you drill these wells, a lot of the production comes online with very little to any incremental operating cost. So at a reasonable oil price, these can be anywhere from 6-month paybacks to 12-month paybacks. We've had some of the A50 payback in 4 months. So this is an area where you can see some really good cash-on-cash returns. And certainly, that's something that we're focused on given the strong payback periods. But once again, we've taken a lot of lessons that we learned from the '24 program, applying to the '25 program and plan to kick that program off in, call it, the early March time frame. A lot more information that we will provide as we move forward, especially in correlation with the fourth quarter earnings announcement in early March. That brings us to the recent deal announcement. This is a really exciting opportunity for Amplify, where we've been looking for a second organic development area onshore that can really complement our exciting offshore opportunities. And as I went through most of those other areas, you'll have heard that while they're certainly all good assets producing solid cash flows, there's just a limit on how much incremental development activity there is in those areas. The acquisition of these Rockies assets through basically 2 portfolio companies of Juniper Capital provides an opportunity to do a lot of things. If you want to go to Slide 5, Michael, and we can talk more about these in the guise of answering questions. But one, it's going to provide a substantial amount of incremental free cash flow, which we can allocate to the best projects across the portfolio. In the near term, I expect that will be a lot of incremental opportunities to develop Beta maybe a little bit faster than we would have been able to as a stand-alone. And so this is an area where we're certainly focused on, as we bring these properties in, they're going to generate a lot of cash flow for the company, and we'll allocate that appropriately. In addition, this brings in a lot of possible organic value creation. This is almost 300,000 acres of really interesting opportunities across the DJ and Powder River Basins in Wyoming. Near term, I expect most of our activity will be in the DJ Basin, where we've identified a number of opportunities near term. Over time, I expect we'll explore more into the Powder River Basin. There is multiple benches. There's a number of opportunities across this very large acreage position where almost 200,000 of the acres are in the Powder River Basin. That's an area where I think longer term, there's going to be a lot of incremental development, a lot of increases in services that will help drive down costs. We're looking at different ways to drill and complete those wells over time. I think you'll see longer laterals and improving economics across that area as that matures in the next few years. And certainly, we intend to be part of that as part of the acquisition. We'll skip inorganic value creation opportunities for a second. We'll go down to efficiencies. Another major reason for this deal is we have a public company scale where we have $27 million a year of cash G&A at the company. A lot of that is just based on being a public company. And then you're in a number of basins. And so there you have kind of a little bit of split in how your overhead has to be allocated across basins. From an organizational perspective, adding incremental properties with very little incremental overhead expense dramatically decreases your burden on basically your value creation from that overhead. So if we can still add a significant amount of incremental production while only adding a very small amount of incremental overhead, that's going to be far more accretive to shareholders on per BOE and a per share basis. And so we're allocating that overhead over a much larger base, which will be very accretive to shareholders. And then on the LOE side, this is an area where you're going to generate much higher netbacks than the existing portfolio, much higher revenue per BOE, whereas the LOE per BOE is actually lower. And I think over time, we can get it even lower than where we are right now. And so this is an area where we think we can be very positive in terms of generating larger margin for the company, which is very beneficial in an area where oil prices have certainly been volatile. And with a couple of areas with higher fixed costs, having an area where you've got kind of that wider margins that you can allocate capital in different environments is going to be very beneficial to the company. We talked a little bit about scale already, but we're adding eventually a 60% increase in PD, PV-10. We'll talk about PD and PV-10 along the way here. But in addition, we're adding almost 75%, 80% increase in oil production. Oil is obviously where you have your much higher margins. It's an area where I think longer term, the oil economics are much better than gas, even though gas is a good tailwind right now with the LNG projects and some of what's going on in Europe. But longer term, gas is much easier to drill for and to develop than oil, especially some of the oilier basins are getting gassier over time. And so I think that's an opportunity. Having an opportunity to add strong oil-producing areas at a very reasonable price is going to pay big dividends for the company down the road. I'm going to go back now to inorganic value creation opportunities and tie two things together. One, obviously, this is an area where we think that there's potential for incremental consolidation. I think that would be coupled with efficiencies in terms of looking at ways to optimize our existing portfolio as well. The idea is not to be in 6, 7 basins long term. The idea is to look at where we can really create value. And if we can't create value from those positions, maybe those are positions we don't need longer term. Certainly, that's something that we will be looking at and once again, if we can drive down overhead costs that are then be allocated over the production base. So idea of maybe growing more in the Rockies as well, maybe reducing our footprint in some of these other areas where we don't have the same growth potential, that's something that the company will and needs to be looking at, once again, all in an idea of becoming more efficient over time and really focusing on these areas where you have the best opportunity for scale, organic development and future value creation. So I'll stop there. I'm sure there's going to be a number of questions. And I think Jeff gave me 5 or 10 minutes, and I've probably way overshot that. So I'll stop talking for a little bit and let Jeff fire away.

Perfect. Thanks, Martyn. [Operator Instructions] So maybe if we start on these new assets, Martyn, I mean, obviously, it's a perfect slide to work off of. It improves a number of different metrics as well as qualitative factors for you guys. But I'm wondering, I'm sure this wasn't the only asset acquisition you looked at over the last couple of years. I'm curious what were the main attributes you guys were looking at. Was it finding something with more growth potential? Was it improving the oil weighting, improving the cost structure? Did it need to hit all of those? I'm just kind of curious, what are the most kind of salient points you think us and investors should take away about what this asset does for Amplify relative to other opportunities you maybe were looking at?

Yes. Listen, we looked at a lot of opportunities in terms of there's a lot of opportunities. We've been pursuing strategic discussions for the better part of the last 2 years, looking at opportunities where -- and obviously, all this will come out, and we've talked about it. But every strategic potential was analyzed in terms of what could create the most potential value for Amplify shareholders. If it's a sale of the company, we looked at that. If there was breaking it up and selling it into pieces, we looked at that. And really, we focused on ultimately this transaction because we feel like -- for two reasons. One, if there had been a transaction kind of where maybe Oklahoma or East Texas we had been able to kind of generate scale and incremental organic development opportunities, an area where we could really focus on and kind of create those efficiencies over time for the organization, I think that would have potentially worked as well. That acquisition just didn't avail itself. So our criteria for looking outside of our existing areas was always about getting enough scale to grow around it. And certainly, the Powder and the DJ are much more established basins from kind of a marketability perspective, and kind of getting that oily production is certainly something where I think it's going to pay big dividends down the road versus -- like I said, gas is better this year than the last couple of years, it's been $2.50 and below kind of or $2.70, I think it was in '23, maybe low $2.20s or something like that in '24. So this is an area where, like I said, we thought that there's a much better long-term value proposition in these particular areas. And then there was at least from an opportunity perspective in terms of what we could bring into the company from the existing portfolio. So that was kind of the rationale was really we were looking at opportunities across all areas. And really, as you start kind of checking boxes on potential deals, this one, while you would love to have found something in an existing basin potentially where it would provide the same kind of scale and organic development opportunities, if that's not available, the next best thing is to find an area where you have that substantial scale. And then it checks a lot of other boxes where you've got, like I said, that oilier production, you're in a much more marketable kind of area of the world. And like I said, you've got a lot of room to grow over time.

A question on the operational side of this new asset. So Amplify has not obviously historically been a tremendously active driller of new wells. So what should we expect in terms of the operational makeup? Will you just be taking on the existing teams that Juniper had running these assets? Will it be kind of a mix between Amplify legacy and new? Or how should we think about that?

Jeff, here currently at Amplify, we have a lot of skilled engineers, geologists who historically has worked a lot of resource plays similar to this one. And then we will more than likely supplement that with some of the teams that have been working this asset over the past 5 years or so and then also look for outside talent. But we feel very confident. The drilling in the DJ is fairly benign, which is another great attribute of this. And the Powder, as Martyn said, probably not as much development for us there near term as opposed to the DJ, but as we start seeing activity in other operators in the Powder, we'll be building the team there when those opportunities present themselves.

Perfect. We got a question on the activity levels on the asset. Is there any active development on either of these assets that you're inheriting? And what kind of CapEx program do you guys envision for these assets over the next couple of years?

Yes, I'll start and Dan, you jump in. So we'll probably, like I said, start slower. I made the same -- mentioned on the last call. I think we have 4 wells scheduled for this year. To hold production flat, it's probably 6 to 7 wells. But I think we're not as worried about kind of keeping one part of the field. This has been the same methodology we've used throughout our time at Amplify. The capital is going to go to the highest value projects. And so near term, while we kind of bring this asset in, we'll probably focus on maybe drilling 4 wells this year and ramping that up starting maybe next year. And then the year after, you can start to, like I said, incorporate more wells maybe in the Powder as well. But we'll probably start a little slower. Two of those wells are actually going to be drilled next month by the existing portfolio teams. We'll obviously coordinate with those teams and be involved in the planning for the drilling. The completion of those wells is likely to be a kind of a late second quarter event. So depending on the timing of the transaction, I would expect that would be under our watch as opposed to the existing teams. And so we're obviously going to be very involved in the planning for both the drilling and the completion, but the drilling itself would happen pre-closing and the completion would happen after closing. And then obviously, we will look at additional couple of wells potentially in the second half of the year. But we could also take what we were going to allocate to those wells and move that to a different area as well. So once we've kind of brought all these assets together, it's going to compete for capital just like everything else. And we're going to make decisions on what's best for kind of the overall portfolio and really kind of allocate our capital that way. Dan, anything you'd like to add?

Yes, that's right. In the DJ, yes, there's not a continuous rig running, but the team that has drilled dozens of these wells over the past 5 years has a rig drilling soon, a specific pad there. And the team has done a great job. We look at historical drilling costs and times and everything. The most relevant comp is EOG has all the acreage just to the west of us, largely drilled it up and very comparable to their results. So yes, we'll go from there and the completion, we'll be lining that up as well. So I think everything is lined up for the next several months there.

Great. Okay. And given that it seems like -- I think you guys disclosed, I think, hundreds of locations or something to that effect on the asset, so good inventory life. You guys have historically run a very free cash flow generative company. How do you guys think about balancing that? This is kind of outside of Beta, which has some nice growth potential. It seems like you guys could potentially accelerate growth at the trade-off of the free cash generation. How do you guys think about it? Does this change or modify Amplify's interest in free cash generation? Or should we expect that to still be kind of a core tenet of the strategy?

Yes, I'll take that. And Jim, if you want to jump in at any point. But I think there's always kind of a trade-off, especially in kind of the tax regime that we've looked at, I think making sure that we're spending a prudent amount of capital to manage kind of the growth of the company. So if you're growing cash flow through drilling Beta wells and if we're kind of managing the overall portfolio and reducing some of our capital needs on other parts of the portfolio, then I think you can start to allocate more to, say, the Rockies over time without seriously denting your ability to generate free cash flow. And certainly, our forecast still have a substantial amount of future cash flow in them as we consolidate these assets. And so once again, there'll be a natural progression from kind of where we start to where we end up and part of that may come through, like I said, reducing our footprint in other areas and reallocating capital appropriately. Jim, is there anything you'd like to add?

Yes. No, I mean, I think Martyn hit it upfront, right? We think this is going to be a free cash flow accretive deal from day 1. So it just gives us a lot more optionality, right? So I think initially, we'll be generating free cash flow and likely paying down debt. And then over time, if we're getting good returns on the development that we're doing, we'll allocate capital there. But I think we'll always be prudent with that capital. That's always been our orientation.

Okay. Perfect. I got a question on Beta, so maybe shifting over to that asset. Can you talk about what you guys have learned about this asset throughout 2024 and the wells you guys have drilled over the past year or so?

Great question.

Yes. Yes, it is. We've learned a lot. We learned when you get the well drilled in the reservoir we picked, they can be extremely good wells as we've seen so far this year on our first few wells. We've also learned some of the drilling hazards we've run into has caused like the C59 we talked about on our last call, got the well drilled, came on very good, well above type, a great well. But it took us about 45 days to drill that well, about 40 days to drill that well, as opposed to we're aiming for 25, 30 days. We're implementing a few things in 2025 that we hope to help with that, drill these faster, more consistently. Managed pressure drilling is a technology used all over the world, but hadn't been used out here in the Pacific. We're going to be implementing that. We also have contingencies we're getting in place, expandable liners, drilling well casing to get casing down. So just really enhancing our toolbox in terms of the technical things we can do to get these wells drilled consistently quicker and hopefully cheaper. So we're excited about doing all that. Outside of that, in terms of the deliverability of these wells, our estimation of where the remaining oil is, and we've kind of proven it up with the wells we drilled, they've all been very oil saturated. So we still feel very good about the geology and the remaining reserves of this reservoir from the experiences we saw in 2024.

Great. Maybe a related question is, what are the major constraints to ramping up development at Beta Field? And is there an upper bound to what we should think of as a realistic development program for the asset?

I can start. So one constraint we have is we own the rigs that drill these wells. So these aren't third-party contracted rigs. We have 2 rigs on 2 separate platforms that were built into the platforms in the '80s by Shell when they developed this infrastructure. So those are the 2 rigs we have to drill with. And then currently, we only employ 1 drilling team, and that's a team of 35 people working day/night shift, 24 hours, 2 weeks on, 2 weeks off. So that's the current risk constraint. We can only run 1 rig at a time. And when we're not drilling new wells, those rigs also do maintenance work. So all these wells, the old ones and the new ones, are run by electric submersible pumps. And these pumps' lives last about 5 years. So at certain times, you have wells go down, and it's about a week to pull one of those wells, replace the pump, run it back in and get that well back to production. So the demand of this rig crew and the 1 rig we run at a time is split between drilling new wells, which I hope take around 30 days, and we expect 10 to 12 wells fail a year. And then we also have some injector like maintenance work, cleanouts, things like that, to do. So that's one constraint we have. That can be alleviated over time if we put the investment into hiring a second rig group. So you run both rigs at the same time. There's a little strain on services out there, but that's something, as we continue to be successful out there, we can certainly start looking at, and we plan to, but not in 2025.

Yes. And just to kind of expand on Dan's point, the idea of running both rigs at the same time is obviously something that we're thinking through. But I think it would be more likely to do drilling on one and maybe a workover on the other. One of the problems that we have is you drill wells back to back and you lose a few workover wells that need workover during the time that you're drilling. If you're drilling 60, 75 days in a row, if you have wells that go down during that time, you might be down 300 to 400, 500 barrels a day that is offline before you can get those wells on. And so it's a balancing act of trying to manage your existing portfolio of wells while you're also wanting to drill for new wells. So we are looking at kind of options where maybe we have an extra crew to kind of keep up with workovers on one platform, but that would only work -- you'd still have the issue, if you're drilling on one platform, you couldn't do a workover on that same platform at the same time. And so it depends on where the workover needs are. So that's one option. But that isn't an incremental cost, and that's something that you have to kind of burden the asset with. But it might be worth it to keep some of these wells online, like I said, because you can't necessarily get to them until you're done with the drilling. Obviously, in a perfect world scenario, you could potentially have 2 drilling crews, but that's 8 crews of people. That's a lot of incremental development. Trying to manage services and scheduling and planning for that many people would be a very big task. So in terms of wells per year, I think drilling 6 is certainly doable. With kind of the current configuration, maybe you can get that up to 7 or 8. To go beyond that, you would need to have at least another crew to manage workovers on whichever platform you weren't working on. And if your program is mostly on one platform during the year, if we're doing a bunch of wells on Eureka, then you're still going to have to interrupt the drilling time to time in order to do those workovers on Eureka, even if you had a second crew that could do anything that pops up on Ellen. So that's kind of the constraint that we're working with. And as we've made these changes to the development program this year and really looking at kind of how those flow through from an economic perspective, are we drilling faster, better, more efficient wells, then certainly, like I said, you'd want to try to do more. Like I said, this even comes back to your allocation of what you're going to do with the cash flow. The better the results, the more you're going to allocate. But like I said, there's trade-offs right now between drilling new wells and potentially losing production on your base of wells. And so we have to manage that. And so those are kind of the constraints. There's near-term constraints, which can be alleviated somewhat over time. Long term, there's some constraints on overall infrastructure. But if we have that problem, I think we're all extremely happy. And so that's more in the kind of the 20,000 barrels a day type range, maybe a little less than that, but it's somewhere in that ballpark where you'd have issues with being able to actually ship all that oil, but that's a much larger constraint hopefully. I'd love to have that problem and maybe we will at some point, but that's kind of a longer-term high-value problem versus kind of where we are right now.

Yes. Okay. That's really helpful. We've got a question on the regulatory side of things there, but I think maybe it might also be helpful. I would assume a lot of people see the dot on the map of California and maybe take a deep breath, but I think it's maybe helpful to cover what is operating in federal waters there, compare and contrast, versus what maybe people might assume for a "California asset." But the question we got also pertains to, with the change in administration and a focus on enabling oil and gas companies to accelerate development from a permitting regulatory standpoint, does that matter or affect the company at all California or anywhere else?

Once again, a great question, whoever asked that. So let me cover California first. So we are in federal waters offshore California. So the good news there is we don't really deal with the state very often. We have a right of way through state waters that we would have to renew every so often, but it's not actually something that can impede us from continuing to produce. So it's something where we deal with the state on an every few years basis, but it's not an overly impactful part of the business. So generally, day-to-day, BSEE and BOEM do most of our kind of regulations. And quite frankly, maybe at the higher political levels, in the prior administration, there was more pushback at kind of the local level. They've been nothing but supportive, easy to work with, very fast. We can probably flip permits there as fast as pretty much anywhere in the country. It's a BSEE and BOEM office that's dedicated to offshore California and Alaska primarily. And there's only really 3 operators in federal waters offshore California. So you can get a lot of attention quickly, and they're extremely supportive of us developing this area. And so I don't have any complaints about working with them day to day. They've been nothing but great to work with. And I can only imagine that will get better, if anything, under this new administration. But I don't see any -- we didn't really have any permitting problems beforehand. So I don't expect to have any major benefits, but there wasn't a whole lot more that they could have done better anyway. And so obviously, from the broader federal government perspective, there are some things, not just in California, but across anything from a waste emissions charges that came into play this year where we had a small impact on our East Texas areas. The BLM in Wyoming has been fairly difficult in terms of -- and it's not really the BLM, it's dealing with some issues from third parties against the BLM. Permitting and leasing new acreage has been slower. That might be something that certainly gets alleviated and that would help significantly with Rockies area development. So certainly, during the next administration, if that eases up, what you'd want to do is go ahead and permit a bunch of new wells and kind of have those in your inventory. And so some of the other things that we have to deal with, like I said, the BSEE and BOEM side, kind of longer-term decommissioning calculations, things of that nature, I think should potentially be improved as well. So certainly, things like that can get better. But from a day-to-day perspective out in California, things are already pretty good because of who we get to work with. We get inspected a lot more often than anyone probably does in the Gulf just because once again, there's less operators, less development. But I find that to be a good thing. It keeps you operating at a very high standard all the time. These platforms were developed very well by Shell in the '80s. And obviously, we maintain them at a very high standard. So I think our standards are a lot higher than maybe they're expected to be in the Gulf, but I consider that a good thing. And like I said, it leads to better overall execution, better relationships and, like I said, less risk for all of us in operating the asset.

Great. We got a question on the natural gas side of things. I believe you guys have disclosed participating in some wells in East Texas. How much is natural gas a part of the story at all? What kind of capital allocation do you guys expect, especially given the firming up of natural gas prices here over the winter?

Yes. I mean I can certainly talk to that. We are participating in a couple of wells in our East Texas position, and then we continue -- so a couple of those are Cotton Valley and then to Haynesville. So where we see the opportunity, when we look at the forward curve, if the economics are supportive and we think we can make economic wells, we tend to participate. Now in East Texas, for folks that are familiar with the story, you'll know this, but we tend to look for deals and find other operators to develop those horizontal wells on our behalf, operators that have more scale and can actually drive down costs better than we can with our acreage position. So yes, we're encouraged, obviously, by gas prices and where they've been this cold winter. Getting 3 inches of snow in Houston is certainly helpful for gas prices. But longer term, like Martyn pointed out, I think we're thoughtful about where it might ultimately head, especially with the new drilling that can come on and the economics of those. So going to an oilier weighted portfolio, I think, is the right direction for us. But certainly, gas still continues to play a pretty big role in our portfolio, and we'll continue to participate in those opportunities as they come up.

Yes. And I'll just supplement that. We have an AMI out in East Texas, where we're drilling these 4 wells under that AMI. I would expect that they will likely propose additional wells once these wells are kind of completed and online. So we'll have additional opportunities through those partnerships. There may be additional opportunities to utilize some of our other Haynesville acreage in transactions or deals that could give us additional participation in the coming years as well. But relatively, as I've said and as Jim just said, it's a smaller piece of the overall. Because even as good as prices look right now, from a pure margin perspective, oil is still far superior, especially in these kind of oilier areas. And like I said, in the Wyoming area, the margin percentage is much higher relative to these gas unless you're drilling -- if you've got an entire new portfolio of Haynesville wells, maybe that's fairly competitive. But when you're mixing in legacy production where it's a little lower margin on gas, it just doesn't have quite the same economics as oil does. And you've really got to believe in gas being $3.50, $4 long term to have kind of similar long-term margins to what you can get on the oil side.

Yes. The only other thing I'd point out, too, right, we've been pretty active hedgers on the natural gas side, right? That's mostly our PDP production. So to the extent we do add incremental wells, new volumes, that could be new volumes to hedge if we thought that was the right thing to do. And then the way we construct our book, right, we have a decent amount of swaps, but also collars, right? So to the extent you're seeing a run-up in price here in the winter, we are participating in some of that upside as well. So we like to be thoughtful and manage our portfolio, the risk, commodity price risk with our hedge book, but we also leave ourselves some upside when we have events like this.

Okay. Perfect. I think we'll get a couple more in here before we wrap up. Question on the hedging front since you were on that, Jim. Does Juniper have any hedges you'll be inheriting? And if not, can you proactively hedge any of those barrels? Or do you need to wait until the transaction closes to do anything there?

Yes. So they do have a hedge book themselves, right? So right now, their position is hedged. And as it comes over, we'll look at kind of how to integrate that into our portfolio, what's the best way to do that. And then also the tenor of those positions, we'll take a more thorough look at that as it fits into our entire portfolio. But right now, we're good and so limited exposure until close.

Yes. They do have the ability to hedge themselves of their own accord during this kind of interim time period. And to the extent that they -- they are less hedged relatively than we are, so they do have a little bit more incremental opportunity to hedge near term. And so obviously, until we close, it's their decision. But we coordinate on a lot of things, and obviously, we'll look at that if it makes sense. But once again, we do have existing hedging with them that will likely all come over, but there's a little bit more room than what we have in our portfolio.

Got it. Okay. Helpful. And then I think this might be the last one I'll wrap up with. On the balance sheet side of things, Juniper has some debt that you guys will be taking on. Will that just be tacked on to the existing RBL? Or are there other solutions under consideration? And what do you guys kind of view as kind of the near-term capital allocation uses, if you will, of free cash? Is it just to start paying down this inherited debt? Or are there other things under consideration?

Yes, I can take that. And Martyn, jump in, obviously. So first question, right, we're trying to figure out what the right debt structure will look like post close, and we're working with the Juniper team to try to figure that out. Certainly, the RBL will be a piece of that and whether there's something on top of that may also be the case, but it may all be under an RBL. We just got to try to figure out what the best fit for us, Jeff, is and what gives us the most flexibility. Certainly, having more scale helps us, right? That's another benefit we don't necessarily talk about, but having more scale helps us vis-a-vis debt options that we could potentially do. So that's been constructive for us. And then the second part of the question, remind me again.

Capital allocation and kind of uses of free cash.

Thank you. Yes. So I think initially, right, with this transaction, we may be slightly more -- we might have slightly more debt than we do today. But over time, because of that free cash flow generation potential, I imagine we'll be paying that down. We've always said we want to be somewhere between 0.5 turn and 1 turn of leverage, and I think that still remains our goal. So upfront, I imagine we'll be using the free cash flow to bring that debt back in line.

Yes. And there's more than one way to kind of do that, obviously, you can do it through free cash flow if we decide to move on from one particular portfolio asset, for example, that's another way to kind of accelerate that down. But now I think Jim hit on all the salient points that we're going to have some flexibility. We might put in kind of a little bit longer-term debt than just an RBL, just to kind of balance it out a little bit more because we do expect to be a little bit more active, especially at the Beta near term and kind of having a little bit more flexibility to utilize capital and then obviously pay it down when we get kind of -- potentially make some changes that would be beneficial. And so to kind of have that maybe a little piece of it that's kind of a little bit longer term and then the RBL for the majority is probably the way we think we're going to go. But we are actively working on that, and we'll obviously put it in place in conjunction with closing the transaction.

Perfect. Okay. I think with that, we're a couple of minutes over, so we'll try to keep it as tight as we can. Amplify team, really appreciate you guys making the time, everyone else who attended. Thank you guys as well and sign off, unless Amplify, you guys have anything to wrap up with.

We just wanted to say thank you to everyone for participating today. If there's any questions that we didn't address, please don't hesitate to reach out to Jeff, who can obviously be in contact with us, or reach out to the company directly. And myself, Jim, Michael are always happy to kind of get on the phone call and explain anything in greater detail if there's things you're so curious about. So thank you all.

All right. Thanks, everyone. Have a good rest of the week.

Thank you, Jeff.